1. Technical Field of the Invention
The present Invention relates to techniques for stimulating the production of oil and gas from a reservoir. In particular, the present Invention relates to specialized techniques of propped hydraulic fracturing, in which the perforations are shot in a plane aligned with the direction of probable fracture propagation, thereafter the fracturing treatment is performed using a low viscosity fluid.
2. Introduction to the Technology
The present Invention relates generally to hydrocarbon (petroleum and natural gas) production from wells drilled in the earth. Obviously, it is desirable to maximize both the rate of flow and the overall capacity of hydrocarbon from the subsurface formation to the surface, where it can be recovered. One set of techniques to do this is referred to as stimulation techniques, and one such technique, xe2x80x9chydraulic fracturing,xe2x80x9d is the subject of the present Invention. The rate of flow, or xe2x80x9cproductionxe2x80x9d of hydrocarbon from a geologic formation is naturally dependent on numerous factors. One of these factors is the radius of the borehole; as the bore radius increases, the production rate increases, everything else being equal. Another, related to the first, is the flowpaths from the formation to the borehole available to the migrating hydrocarbon.
Drilling a hole in the subsurface is expensivexe2x80x94which limits the number of wells that can be economically drilledxe2x80x94and this expense only generally increases as the size of the hole increases. Additionally, a larger hole creates greater instability to the geologic formation, thus increasing the chances that the formation will shift around the wellbore and therefore damage the wellbore (and at worse collapse). So, while a larger borehole will, in theory, increase hydrocarbon production, it is impractical, and there is a significant downside. Yet, a fracture or large crack within the producing zone of the geologic formation, originating from and radiating out from the wellbore, can actually increase the xe2x80x9ceffectivexe2x80x9d (as opposed to xe2x80x9cactualxe2x80x9d) wellbore radius, thus, the well behaves (in terms of production rate) as if the entire wellbore radius were much larger.
Fracturing (generally speaking, there are two types, acid fracturing and propped fracturing, the latter is of primary interest here) thus refers to methods used to stimulate the production of fluids resident in the subsurface, e.g., oil, natural gas, and brines. Hydraulic fracturing involves literally breaking or fracturing a portion of the surrounding strata, by injecting a specialized fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation. More particularly, a fluid is injected through a wellbore; the fluid exits through holes (perforations in the well casing lining the borehole) and is directed against the face of the formation (sometimes wells are completed openhole where no casing and therefore no perforations exist so the fluid is injected through the wellbore and directly to the formation face) at a pressure and flow rate sufficient to overcome the minimum in-situ rock stress (also known as minimum principal stress) and to initiate and/or extend a fracture(s) into the formation. Actually, what is created by this process is not always a single fracture, but a fracture zone, i.e., a zone having multiple fractures, or cracks in the formation, through which hydrocarbon can flow to the wellbore.
In practice, fracturing a well is a highly complex operation performed with precise and exquisite orchestration of equipment, highly skilled engineers and technicians, and powerful integrated computers monitoring rates, pressures, volumes, etc. During a typical fracturing job, large quantities of materials often in excess of a quarter of a million gallons of fluid, will be pumped at high pressures exceeding the minimum principal stress down a well to a location often thousands of feet below the surface.
Thus, once the well has been drilled, fractures are often deliberately introduced in the formation, as a means of stimulating production, by increasing the effective wellbore radius. Clearly then, the longer the fracture, the greater the effective wellbore radius. More precisely, wells that have been hydraulically fractured exhibit both radial flow around the wellbore (conventional) and linear flow from the hydrocarbon-bearing formation to the fracture, and further linear flow along the fracture to the wellbore. Therefore, hydraulic fracturing is a common means to stimulate hydrocarbon production in low permeability formations. In addition, fracturing has also been used to stimulate production in high permeability formations. Obviously, if fracturing is desirable in a particular instance, then it is also desirable, generally speaking, to create as large (i.e., long) a fracture zone as possiblexe2x80x94e.g., a larger fracture means an enlarged flowpaths from the hydrocarbon migrating towards the wellbore and to the surface.
The Prior Art
The present Invention combines disparate technologies from the prior art, which when combined, produce unexpectedly superior resultsxe2x80x94as evidenced by results obtained in an actual field setting, which shall be discussed later.
The prior art upon which the present Invention is based is the general teaching of the shooting perforations oriented in the direction in which the fracture is most likely to propagate. This way, potentially large pressure drops caused by the tortuous flowpath that the fluid must take, are eliminated, in turn allowing the well operator to perform fracture treatments. (See, e.g., H. H. Abass, et al., Oriented Perforations: A Rock Mechanics View, SPE 28555 (1994); C. H. Yew and Y. Li, Fracturing of A Deviated Well, SPE 16930 (1987), both papers are hereby incorporated by reference in their entirety).
A second major area of prior art subsumed in the present Invention is low viscosity fracturing fluids. In particular, such low viscosity fracturing fluids include water and viscoelastic surfactant-based fracturing fluids. (See, e.g., U.S. Pat. No. 5,551,516, Hydraulic Fracturing Process and Compositions, assigned to Schlumberger). These unique viscoelastic surfactant-based fracturing fluids shall be described in more detail later.
The novelty of the present Invention resides in the combination of the steps of properly orienting perforations in a well casing relative to pre-determined stress fields, so that the perforations are aligned in the direction of likely fracture propagation plus the step of creating a propped fracture by means of a low viscosity fracturing fluid.
Preferred embodiments of the present Invention are directed to fracturing treatments in very tight gas-producing formations, and in particular, those having very high stress contrasts between the producing zones and the bounding layers.
The present Invention possesses numerous very significant advantages over the prior art. These shall be explained below.
A fracture will propagate in the direction perpendicular to the formation""s minimum in situ stress. If the perforations are not oriented in that direction, the fracturing fluid does not take the most direct route into the fracture. Instead, the fluid exits the perforation (under tremendous pressure) and begins to fracture the formation directly opposite the perforation. Eventually, the fluid is redirected towards in the direction of maximum in situ stress (i.e., the path of least resistance); it is in this direction that the major fracture eventually propagates. Hence, the fluidxe2x80x94rather than travelling in the most direct route (from the perforation directly into the formation) takes a more tortuous route into the formation. This effectxe2x80x94often referred to as xe2x80x9cnear-wellbore tortuosityxe2x80x9d xe2x80x94is highly undesirable. (It is also well documented in the literature, see, e.g., R. G. van de Ketterij and C. J. de Pater, Impact of Perforations on Hydraulic Fracture Tortuosity, 14(2) SPE Prod. and Facilities 131 (1999). The reason is that near-wellbore tortuosity leads to often large pressure lossesxe2x80x94in other words, as the fluid is redirected from its immediate exit to the direction in which it eventually travels, its pressure understandably decreases. In response to this adverse effect, the fluid must be initially pumped at higher pressures than are actually required (if the perforations had been optimally aligned). Higher pumping pressures require greater horsepower and therefore increase the cost of the treatment. Aside from higher pumping pressures, another response is to use a higher viscosity fluid (higher than is ordinarily needed to deliver the proppant). Yet higher viscosity fluids also require greater horsepower to pump, but more significantly, they are more damaging to the newly propped fracture because the fluid is difficult to remove from the placed proppant pack. And aside from this, higher viscosity fluids tend, on average, to be require additional breakers, thus further increasing the cost of the treatment.
Again, as we have stated, the primary advantage of properly oriented perforations is that it allows lower pumping pressures, thus increasing treatment cost. In addition though, this allows the use of lower viscosity fluids. In the present Application, we have found that particular types of low viscosity fluids when used in conjunction with precisely oriented perforations, give rise fractures of surprising effectiveness. By xe2x80x9ceffectivenessxe2x80x9d we mean fractures of optimum heightxe2x80x94substantial height yet still that do not reach the bounding (non-producing) layers; and optimum length. The enhanced length is due to the remarkable ability of the fluids of the present Invention to clean-up, or be removed from the fracture after the fluid has successfully delivered the proppant. As we shall demonstrate, the conventional polymer-based fluid, under the same conditions, would give rise to a fracture out of zone (based on computer modeling results).